CO2 capture technology continues to gain viability in making coal-fired and coal gasification generation competitive, environmentally-friendly options as compared to gas-fired generation. It is expected that 60-65% of the CO2 from coal-fired or gasification power plants needs to be removed from the exhaust of a coal-based generation system to make those systems equivalent to gas-fired generation systems. As CO2 capture technology continues to advance, however, conventional CO2 sequestration techniques have been unable to meet the ever increasing storage demands associated with conventional CO2 capture technology.
One conventional CO2 sequestration technique involves injecting CO2 into deep underground wells. Regulators have assured the public that deep well CO2 capture is safe by requiring that natural geologic caps be present to prevent release of CO2 to the Earth's surface. The use of natural geologic caps has been predicated on the use of pure CO2 injection into the ground. Pure CO2 sequestered from power plants has found conventional uses for either enhancing oil production or storage in “dome” features. The majority of power plants, however, are not in locations where these options are readily available, thus requiring lengthy and expensive pipelines to transport captured CO2 to such locations. Instead, a majority of power plants are located in areas where deep saline aquifers are present.
The saline aquifers in deep formations already have many of the ions needed to form long term storage carbonate minerals. Accordingly, conventional techniques have sought to capitalize on this characteristic by injecting gaseous or supercritical (free phase) CO2 directly into the aquifers. Free phase CO2 injection, however, suffers from the potential risk that the CO2 does not dissolve into aquifer water fast enough to remove the risk of release back to the Earth's surface. Specifically, the density of CO2 gas and liquid in the aquifer is much lower than that of native aquifer water, creating a strong tendency for the CO2 to make its way upward.
There are many other disadvantages associated with injecting gaseous CO2 directly into aquifers. For example, there is a potential for casing failure above the desired injection point. Any leakage in the deep well casing above the desired injection point can release CO2 gas and liquid into shallower formations, e.g., potable water supplies. Due to the fact that the CO2 gas is less dense than aquifer water, the risk of CO2 release to the Earth's surface is exacerbated. Additionally, CO2 leakage through the casing in a well injecting pure CO2 gas will not be detected quickly because any changes in well backpressure may be too small to be noticed in a reasonable timeframe due in part to the high pressures at which conventional wells operate. Further, for a gas, measurements of pressure, temperature, and volume flow rate are all needed to assess mass rate, thus making the assessment difficult to ascertain.
Another disadvantage to deep well injection of CO2 gas is the potential problems with CO2-hydrate formation in pipelines, near valves, and in injection wells. There may be a significant pressure drop from delivery pressure past the injection well choke or flow regulation valve. At startup, a significant pressure drop will also be present between the inside of the well and the aquifer so that gas cooling occurs. These pressure drops can cool the CO2 gas enough to promote the formation of CO2-hydrates as the gas enters the aquifer. Such hydrates may be slow to dissolve and also inhibit the flow of gas into the aquifer. One conventional solution for this problem is to use methanol injection with the gaseous CO2 into the well for hydrate inhibition, but such a solution both significantly raises costs associated with CO2 sequestration and creates an unsafe fire hazard.
Therefore, there is a desire for improved systems and methods for CO2 sequestration that overcome the disadvantages of conventional techniques discussed above. Various embodiments of the present invention address these desires.